rdöls - Organische Geochemie · 2018-10-22 · k – rdöls •The main force driving Secondary Migration secondary migration is the buoyancy of hydrocarbons. •There is a tendency

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Chapter 1 - Expulsion, Migration, Traps

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Expulsion - Migration

Traditionally (Illing, 1933), the process of petroleum migration is divided into two parts:

• primary migration within the low-permeability source rocks,

• secondary migration in permeable carrier beds and reservoir rocks.

It is now recognized that fractured source rocks can also act as carrier beds and reservoir rocks so more modern definitions are:

Primary migration of oil and gas is movement within the fine-grained portion of the mature source rock.

Secondary migration is any movement in carrier rocks or reservoir rocks outside the source rock or movement through fractures within the source rock.

Tertiary migration is movement of a previously formed oil and gas accumulation.

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Secondary Migration

• The main force driving secondary migration is the buoyancyof hydrocarbons.

• There is a tendency for oil and gas to segregate from aqueous phase liquids because of density differences.

• In most cases, the action of gravity leads to a column of gas over oil over water. In a few cases, this does not happen and gravity migration is restricted by capillary forces.

• Capillary pressure is the excess pressure required for oil or gas to displace water from pores.

• If capillary and buoyancy forces are matched, hydrocarbon can be trapped within a particular lithology.

• Hydrodynamic traps of this kind are found when gas is accumulating downdip and below water saturated rocks.


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rdöls Secondary Migration

FLUID PRESSURE

Pressures at 1,000 m (1 km) depth and pressure gradients depend on the saturating fluid and the porous medium densities.

1 bar = 9.8 m H2O = 0.987 atm = 100 kPa = 100 kN/m2 = 14.5 psi = 750 mm Hg = 750 Torr


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Secondary MigrationINTERFACIAL TENSION

When a drop of one immiscible fluid is immersed in another and comes to rest on a solid surface the shape of the resulting interface is governed by the balance of adhesive and cohesive forces.

The surface area at the fluid-fluid contact is minimized by the interaction of these forces:

cohesive forces at the fluid-fluid interface

adhesive forces at the solid-fluid interface

Interfacial tension represents the amount of work needed to create a unit surface area at the interface. The dimension of work is [FL] so interfacial tension is [FL/L2] = [FL-1]. The SI units are N/m or J/m2. Typical values: 0.02 to 0.03 N/m for oil-brine and quartz or calcite.


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Secondary Migration

CONTACT ANGLE

The angle between the fluid and solid phases is called the contact angle. Contact angles are always measured in the denser fluid phase. If θ < 90° the fluid is said to “wet” the surface. If θ > 90° the fluid is said to be “non-wetting”.

adhesion > cohesion =>> “wetting”

cohesion > adhesion =>> “non-wetting”

Water “wets” glass, mercury is “non-wetting” on a glass surface.

Interfacial tension creates a curved interface between two immiscible fluids.


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Secondary Migration

FLUIDS AND PRESSURE

Pressure (P) at any point in a static fluid is equal to the weight of the overlying fluid column:

P = ρ * g * h = * h

where

P is the fluid pressure [F/L2]

ρ is the fluid density [M/L3]

h is the column height [L]

is the fluid specific weight [F/L3]

The pressure gradient dP/dh is thus the specific weight: = ρg.

Fluid specific gravities in reservoir engineering can range from 0.1 for shallow gas to 1.25 for saturated brines: Hydrocarbon gases range from 0.1 to 0.5, condensates from 0.5 to 0.75, oils from 0.75 to 1.0 and formation water from 1.0 to 1.25.


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Secondary Migration

Capillary Forces

Water rises in a capillary tube diameter, 2r, to a height, h.

The downward force is thus:

W = m g = ρ V g = ρ g r2 h = r2 Pc

where Pc = ρ g h is called the capillary pressure.

Pc = Pa – Pw

The downward force of the water is resisted by the interfacial tension at the contact around the diameter of the tube:

r2 Pc = 2r σwa cosθwa

Pc = 2σwa cosθwa r-1


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Secondary Migration

Capillary Forces

The effect of interfacial tension is to create a finite pressure difference between immiscible fluids called the capillary pressure:

Pc = Pnw - Pw

where Pw and Pnw refer to the wetting and nonwetting phases.

Capillary pressure depends on the properties of the fluids and solid surfaces, σwa and cosθwa, and the tube radius, r.

When adhesion > cohesion, adhesive forces draw the fluid up the tube until they are balanced by the weight of the fluid column.

When cohesion > adhesion, cohesive forces drag fluid down the tube until they are balanced by the weight of the head difference forcing fluid upwards.


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Secondary MigrationWETTABILITY

The wettability of a rock refers to the contact angle for the oil-brine interface.

If θ < 90° the reservoir is said to be “water-wet”.

If θ > 90° the reservoir is said to be “oil-wet”.

In oilfield terminology:

0° - 70° strongly water-wet

70° - 110° intermediate wettability

110° - 180° strongly oil-wet

Wettability is affected by factors including:

• fluid compositions

• mineral surface properties

• microbial activity

• temperature and pressure.


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Secondary Migration

Wettability plays a critical role in petroleum production and reservoir engineering.

Oil wet reservoirs tend to become water wet during production or life cycled of a reservoir.

As soon as preferential pathways for „water break through“ are established production decreases and wells may have to be abandoned.


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For a pore-throat diameters between 1 mm and 1 µm, the following capillary pressuresare obtained:

In a fluid-fluid-system the following quartz contact angles and interfacial tension are obtained:


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At elevations greater than the capillary head, hc, the oil saturation is (1 - Swi). At the oil water contact (OWC), ho, the water saturation is 1. Between ho and hc the saturations vary continuously through the capillary transition zone.


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Secondary Migration

INTERFACIAL TENSION CHANGES

Interfacial tensions for oil-water systems range from 0.005 to 0.035 N/m at STP. With increasing temperature and pressure, typicalvalues are 0.01 to 0.02 N/m.

Gas-water systems range from 0.03 to 0.07 N/m at STP. With increasing temperature and pressure these values shift to around 0.022 to 0.025 N/m.

This means that oil migrates more easily than gas through water-wet rock. However, the much higher buoyancy of gas combined with a low viscosity gives gas a considerably greater migration potential.

At even higher T and P, interfacial tensions for oil-water and gas-water systems approach the same value (above the critical point for the system). A single-phase system will form as gas condensate.


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Secondary Migration

PORE THROATS

The critical parameter controlling the value of Pc is pore-throat radius. A hydrodynamic trap will be created at a change in pore-size if buoyancy cannot overcome capillary forces.

A small opening in a water-wet reservoir rejects oil (and gas) whereas a small opening in an oil-wet rock rejects water. Most rocks are water-wet in the subsurface so capillary barriers to petroleum migration are common.

Capillary pressures in shales with pore diameters of 20-50 nm can be massive. For example, for a light crude the value of Pc would be 2400 to 6000 kPa or 24 to 60 atmospheres!

Natural hydrofracturing limits the differential pressure that can be sustained. Microfractures often provide conduits for oil to pass matrix capillary barriers, for example, a 500 nm (0.5 µm) micro-fracture would only require 480 kPa provided by buoyancy to pass.


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Secondary Migration

JOINTS AND FAULTS

Macro-fractures of various type are pervasive in most brittle rocks.

Tensile fractures and normal faults are most likely to provide flow conduits because the fractures tend to be more likely to be open.

Fault breccias often provide zones of high permeability.

Reverse faults (Aufschiebung) tend to be less permeable thannormal faults (Abschiebung) as would be expected from the stress regime (compressive/dilatational) responsible for their formation.

Vertical migration of fluids through fracture systems in both low permeability rocks and reservoir rocks is widely reported in thehydrogeological and petroleum geology literature.

Faults can also act as permeability barriers where clay gouge or other low permeability infill is produced by shearing.


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Secondary Migration

UNCONFORMITIES

Unconformities are usually associated with significant changes in permeabilities and may represent either flow barriers or conduits.

Some petroleum geologists (North, 1985) believe that sub- and intra-Cretaceous unconformities may be the most importantstructural phenomena involved in trapping oil and gas on a worldwide basis.

In western Canada, where the sub-Cretaceous unconformity is underlain by massive sheet sandstones (Mannville), the unconformity can be a permeable migration pathway.

Unconformities often correspond to periods of subaerial erosion when permeability tends to be enhanced.

A large number of oilfields are related to unconformities including both the Venezuelan and western Canadian heavy oil deposits.


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Secondary Migration

TRAPS AND SEALS

A trap is any part of a reservoir that holds commercial quantities of oil. The closure of a trap is the vertical distance from the crest or highest point to the spill point, where the oil spills below the trap into adjacent permeable beds.

A seal is the low permeability interval above the trap.

The gross pay zone in a trap is the distance from the top of the accumulation to the lowest point on the OWC.

The net pay zone is the part of the gross pay interval that is commercially productive.


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Secondary Migration

TRAPS AND SEALS

The three most important properties of a trap are:

1. proximity to HC migration pathways

2. permeability of the seal

3. height of the closure (trap-size).

If a trap is not situated on a migration pathway, it will not accumulate oil. Knowledge of regional paleoflows is critical to the exploration process.

All seals leak. If the seal is too permeable, the trap leakage rate may exceed the rate of migration and no accumulation will occur.

If the closure is small, the accumulation may not be commercially viable. Small pools are difficult to find and expensive to develop.


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Secondary Migration

SEAL PROPERTIES

It is not the matrix permeability but most often the fracturepermeability of a seal that is critical.

Gas hydrates (e.g. permafrost) or regional evaporites (salt and anhydrite) are the best seals. Both gas hydrates and evaporites have the ability to heal fractures over time.

Ductile shales (> 40% clay minerals) are better seals than more brittle fine-grained rocks. Only a small percentage of shales have clay-mineral contents as high as 40%. Most shales are brittle and are readily fractured on a microscopic scale. This is sufficient to render them ineffective as seals.

Stylolites, formed by pressure solution, can at times provide effective seals in carbonates. Asphalt/tar can also act as a seal where oil is degraded near surface and large hydrocarbon molecules block pore-throats.


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Secondary Migration

TRAP INTEGRITY

Structural Traps

In structural traps, such as simple anticlinal traps, the buoyant force tends to be directed vertically upwards and approximately normal to bedding. Sedimentary sequences tend to show vertical changes in lithology and a series of silts and shales can provide an effective seal.

Stratigraphic Traps

In stratigraphic traps, such as a pinchout, the buoyant force is directed up-dip rather than vertically. A single thin silty layer inpinchout can result in loss of seal integrity and no petroleum accumulation will take place.


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Secondary MigrationSECONDARY MIGRATION DISTANCES

About 60% of reservoirs worldwide appear to have accumulated due to preferential vertical migration and 40% due to dominantly lateral migration from the source bed. In many cases, both lateral and vertical migration is involved. Migration distances depend on the size of the basin in which the oil accumulates.

Vertical migration is more efficient than lateral migration but less petroleum is collected because traps can only intercept migrationpathways vertically beneath themselves. Lateral migration can drain a larger volume of source rock.

Basin Type Example % Reserves

Foreland Basin and Fold Belts Alberta 56

Interior Rift North Sea 23

Divergent Margin Gulf Coast 8

Active Margin Los Angeles 6

Interior Cratonic Sag Williston 1

Deltas Mackenzie 6


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rdöls Reservoirs - Traps

Hydrocarbon traps form where permeable reservoir rocks (carbonates, sandstones) are covered by rocks with low permeability (caprocks) that are capable of preventing the hydrocarbons from further upward migration. Typical caprocks are compacted shales, evaporites, and tightly cemented sandstones and carbonate rocks.The caprock need not be 100% impermeable to water, oil or gas. If the upward loss of hydrocarbons is less than the supply of hydrocarbons from the source rocks to the trap, hydrocarbons may still accumulate.


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rdöls Reservoirs - Traps

Various types of migrations routes intercepting reservoir /trap structures that may host petroleum or gas.


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Reservoirs - Traps

Traps are usually classified according to the mechanism that produces the hydrocarbon accumulation.

The two main groups of traps are those that are formed by structural deformation of rocks (structural traps), and those that are related to depositional or diagenetic features in the sedimentary sequence (stratigraphic traps).

Many traps result from both of these factors (strati-structural or combination traps). A common example is stratigraphic pinch-out (e.g., a sandstone lens wedging into mudstone) that is combined with tectonic tilting (which allows hydrocarbons to pond in the updip part of the sandstone wedge).

Other traps result mainly from fracturing (which creates the reservoir porosity) or hydrodynamic processes.

There are many classifications of hydrocarbon traps in use, but most have ~90% in common.


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rdöls Reservoirs – Structural Traps

Structural traps primarily result from folding and/or faulting, or both.

Reverse fault (thrust fault)

Normal fault (extension fault)

Anticlinal (fold) and dome traps combined with thrust sheet


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1. Anticlinal (fold) and dome traps

Necessary conditions: An impervious cap rock and a porous reservoir rock; closure occurs in all directions to prevent leakage (i.e. four-way closure necessary for a dome).

a) Simple fold traps (anticlinal) with axial culmination (fold axis dipping in two or more directions). The simplest type of trap is formed when a sandstone bed that is overlain by tight (i.e. low permeability) shale is folded into an anticline. A simple anticline, however, may not necessarily be a trap. The crest of the anticline must have an apical culmination (i.e. a peak) somewhere along the fold axis so that hydrocarbons can be trapped. Anticlinal traps are commonly detected by seismic reflection. In mature oilfields, most of these simple traps have probably been found, but many anticlinal traps remain to be discovered offshore and in new prospective areas.

b) Salt domes: Strata around the salt dome curve upward creating traps against the sealing salt layers (details follow).

c) Growth domes: Domes or anticlines that form during sedimentation when one area subsides more slowly than the surrounding areas. Their formation is concurrent with sedimentation (i.e. they form during deposition), and not due to later (tectonic) folding. Growth anticlines may form due to differential compaction over salt domes or other upward-projecting features in the substrate (topographic highs on the buried landscape).


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2. Fault traps

The fault plane must have a sealing effect so that it functions as a fluid migration barrier for reservoir rocks. Common types of fault trap:

a) Normal faults — commonly associated with graben (rift) structures.

b) Strike-slip faults — these may not be sealed due to incremental movements, but basement-controlled strike-slip faults commonly produce good anticlinal structures in overlying softer sediments.

c) Thrust faults — commonly associated with compressional tectonics

d) Growth faults — Growth faults typically form in sediments that are deposited rapidly, especially at deltas. Faulting occurs during sedimentation (i.e. syndepo-sitionally), such that the equivalent strata on the downthrow side will be thicker than on the upthrow side. The throw between corresponding strata declines upwards along the fault plane. Minor fault planes with an opposite throw (antithetic faults) may also form in the strata that curve inward towards the main fault plane. The fault plane is commonly sealed, preventing further upward migration of oil and gas. Fault traps may also form when sandstone beds are offset against the fault plane. Some petroleum traps, however, form in "roll-over" anticlines on the down-faulted block. Growth faults may reduce porewatercirculation in sedimentary basins; consequently, undercompacted clays, which may develop into clay diapirs, are often associated with growth faults.


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Growth faults develop upon ongoing sedimentation and thus show increased thickness on downthrown blocks. They often occur in deltas and create good reservoirs when permeable and impermeable strata are in juxtaposition.


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Some general points about efficiency of fault traps

The geometry and timing determine whether faults will be effective in forming fault traps:

1. Dead faults that predate basinal sediments only affect the underlying basement – they play no direct role in hydrocarbon trapping in the younger sedimentary pile.

2. Continuously developing faults (growth faults) — active during sedimentation, forming major petroleum traps (e.g., Niger Delta)

3. Young (late) faults —these form late during sedimentation; depending on their initiation and growth, they may or may not be effective as traps.

4. Late regenerated faults — new movements on old faults — they are more likely to destroy than form traps, but may be effective.


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Important point: Faults are highly ambiguous features. They may leak, serving as permeable conduits for fluid flow (including oil and gas migration), but more commonly act as seals unless they are rejuvenated after petroleum has pooled. They form seals because of fault gouges or differential pressures either side of the fault plane.


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Many petroleum fields are closely linked to faulting, but traps that result from faulting alone are less common.

There are three common fault – petroleum pool associations:

1. The fault itself makes the trap without an ancillary trapping mechanism such as a fold — normal faults are the most common examples.

2. The fault creates another structure (e.g., a fold or horst) that in turn forms the main trap.

3. The fault may be a consequence of another structure that forms the main trap — e.g., the extensional crestal faults that form above some anticlines.


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rdöls Reservoirs – Salt Dome Traps

Salt domes form when salt is less dense than the overlying rock, and the salt moves slowly upwards due to its buoyancy. For this to happen, there must be a minimum overburden and the thickness of the salt deposits must be more than ~100 m. Upward movement of salt through the sedimentary strata, and associated deformation is termed halokinetics or salt tectonics. Movements may continue for several hundred million years. Traps may form:

• in the strata overlying the salt dome,

• in the top of the salt domes (the cap rock - caused bybrecciation and dissolution),

• in the strata that curve upward against the salt intrusion,

• due to stratigraphic pinch-out of strata around the salt dome.

Salt dome reservoirs produce major oilfields where basinal sediments contain thick salt deposits. Salt deposits are common in Permian-Jurassic sediments around the Atlantic Ocean. Examples include the Gulf of Mexico, where there is Permian and Jurassic salt, the Permian Zechstein salt in NW Europe and the North Sea.


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rdöls Reservoirs – Salt Dome Traps


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rdöls Reservoirs – Stratigraphic Traps

Stratigraphic traps are created by any variation in the stratigraphy that is independent of structural deformation, although many stratigraphic traps involve a tectonic component such as tilting of strata. Two main groups can be recognized:

Primary stratigraphic traps result from variations in facies that deve-loped during sedimentation. These include features such as lenses, pinch-outs, and appropriate facies changes. Examples include:

• Primary pinch out of strata, e.g., strata that pinch out updip in less permeable rocks such as shale;

• Fluvial channels of sandstone that are isolated and surrounded by impermeable clay-rich sediments;

• Submarine channels and sandstone turbidites in strata rich in shale;

• Porous reefs that are surrounded by shale, etc.

Secondary stratigraphic traps result from variations that developed after sedimentation, mainly due to diagenesis. These include variations due to porosity enhancement by dissolution or loss by cementation.


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Paleogeomorphic traps are controlled by buried landscape. Some are associated with prominences (hills); others with depressions (valleys). Many are also partly controlled by unconformities so are also termed unconformity traps.

Oil trapped belowunconformity in

paleotopographichighs below

transgressive shales.

Oil trapped aboveunconformity in

paleotopographiclows formed by

porous channel sands.


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rdöls Fractured Reservoirs

Fractured basement rock that projects upward locally into overlying shales can also provide good traps. Fractured, well-cemented rocks (limestones and cherts) along faults may also form good traps of limited lateral extent.

Oil is trapped in fractureporosity below adisconformity.

Oil is trapped in fractureporosity adjacent to

fault plane.


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rdöls Hydrodynamic Reservoirs

If porewater flow in a sedimentarybasin is strong enough, the oil-water contact may deviate from the horizontal because of the hydrodynamic shear stress that is set up. In some cases, oil may accumulate without closure. Flow of fresh (meteoric) water down through oil-bearing rocks commonly results in biodegradation of the oil and formation of asphalt, which may then form a cap rock for oil.


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Case Study

Migration Reconcavo Basin

Onshore Brazil


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rdöls


On-shore and Off-shore Petroleum Basins in Brazil

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rdöls Migration Reconcavo Basin

Main features:

Largest and oldest on-shore petroleum basin in Brazil.

South Atlantic Rift Basin. Boundaries are Apora High towards Tucano Basin in NW, Salvador High in SE.

Basin segmented in 3 sections: Camacari Low, Alagoinhas Low, Quiambina Low.Most important structural element: Mata Catu Fault Trend


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rdöls Early Rifting in South Atlantic


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LithoStrat:

Graben and Half-graben structures filled with organic-rich claystones (source units)

Fluviodeltaic sand-stones and gravels provide reservoirs and migration conduits.

Lateral, fault-associated conglo-merates potentially serve as migration routes.


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Source and reservoir units in Reconcavo Basin:

Source units: Candeias Fm, in particular Gomo Member

Reservoir units: a) Berriasian (Lower Cret.) Agua Grande Fm.b) Tithonian (Upper Jurassic) Sergi Fm.


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Analytical approach: Solvent Flow Through extraction for sequential recovery of petroleum fractions from an intact carrier bed /reservoir pore-system.


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Compositional changes in SFTE fractions recovered from an intact carrier bed /reservoir pore-system. Earliest oil entering the pore system shows low maturity and conditions pore surfaces. Free oil enters open pore lumens late but is recovered early by SFTE.


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Carbazoes constitute a major proportion of heteroaromatics found in crude oils and extracts.

The pyrrolic hydrogen functionality tends to establish hydrogen bridging with activates surfaces, leading to a partitioning of carbazolesthat migrate through a pore system.If positions next to the pyrrolic hydrogen bear functionalities (e.g. alkyl, benzo), a shielding effect minimizes the sorption tendencies leading to differential fractionation.

1

3

2

4

a

c

b


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The first oil entering the pore system is highly polar and adsorbes on pore surfaces, conditioning these for later free oil charges. Early oil charges have high 4/1MC and low BaC/BcC ratios, not indicating longer migration but more intensive interaction with unconditioned surfaces.


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Critical question:Is the Mata Catu Fault a regional seal or a conduit for migrating fluids?

Conceptual approach:

Investigate DST oils and petroleum fractions recovered by SFTE for compositional differences.

Outline potential migration routes from kitchens to reservoirs.


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Migration Reconcavo

Basin

Site MJ-56: Data columns fltr:•Gamma Ray curve•Lithology•Oil shows•Cementation•Poroperm•SFTE extract yield:1st ext, total ext•Thermal maturity: C30dia/ab, C29Ts/ab

•Migration Tracer:4/1-MC, BaC/BcC

4-MC & BaC decreaseby surface interaction(migration distance)


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Organic matter richness or source potential and its associated thermal maturity and oil generation varies laterally in the Reconcavo Basin.

Bulk analyses (TOC, S2, HI) of Candeias Fm. and the Gomo Mbr. source units are available at high resolution.

Therefore, kitchen areas for preferential generation and expulsion of hydrocarbons from source units can be mapped, taking into account source unit volumetrics.


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Migration Reconcavo

Basin

Regional maturity map for the source interval of the Candeias Formation based on vitrinite reflectance analysis.

Kitchen areas with mature to highly mature kerogens are located sw´and nw´of the Mata Catu Trend in the Miranga Low


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Kapitel 3 - Maturation, Migration, Reservoir


Maturity control on migration pattern (reservoir extracts):Migration goes updip from kitchen (lows with high ratios) to a barrier, provided by Mata Catu Fault Trend. Shallow reservoirs contain low maturity oils. Confluence of two routes (green and yellow) near MJ56.

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Maturity/polar fractionation control on migration pattern (extracts): Confluence near MJ56. Near expulsion BaC/BcC ratios are high, low values indicate longer migration routes (e.g. PC1). AG 156 sourced from distant section, see red and blue arrows for potential migration routes.


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Carbazoes constitute a major proportion of heteroaromatics found in crude oils and extracts.

The pyrrolic hydrogen functionality tends to establish hydrogen bridging with activates surfaces, leading to a partitioning of carbazolesThat migrate through a pore system.If positions next to the pyrrolic hydrogen bear functionalities (e.g. alkyl, benzo), a shielding effect minimizes the sorption tendencies leading to differential fractionation.

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Molecular electrostatic potential and partial charges for two main benzocarbazole isomers. Positive charges (blue and purple) near nitrogen functionality and ring system, negative charges occur with pyrrolic hydrogen functionality (red).

Molecular fractionation effectsreported for benzocarbazoles in variable migrations scenarios. Close to source relative proportions of BaC are high but decline upon increasing migration distance.


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Migration Reconcavo

Basin

DSToils: Maturity/Polar fractionation control on migration pattern: confluence near MJ56. Free oil carbazole signatures compared to residual oils. Note high BaC/BcC ratios in free oils indicating less sorptive interaction with minerogenic surfaces or less molecular sieving effects.


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Inferred migration distance (lateral from kitchen to reservoir) correlates well with BaC/BcC ratios for SFTE fractions (left) but shows substantial deviation (right panel) for DST oils. The latter represent free oils that have had less interaction with a pore surface already oil-wet and preconditioned by earlier oil charges.


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Inferred migration distance correlates well with easily to determine 9/1-MP ratios in SFTE fractions (left). These changes are attributed to a molecular sieving effect, with 9-MP being preferentially excluded from interaction with pore matrix. The effect is not controlled by maturity that will dictate the (3+2)/(9+1)-MP ratio, or the MPI.


Documents

rdöls - Organische Geochemie · 2018-10-22 · k – rdöls •The main force driving Secondary Migration secondary migration is the buoyancy of hydrocarbons. •There is a tendency